FIG. 1A illustrates a typical prior art drilling system. During drilling, drilling fluid (“mud”) is pumped by mud pumps 40 through the drill string 30, drill bit 32, and back to the surface through the annulus 14 between drill string 30 and the wellbore 10. While drilling, it is known in the art to use an accelerometer on a tool string downhole to measure tool shock and drilling vibration. This information can alert rig operators when harmful downhole vibrations are occurring that will require a changing in the drilling operation. In addition, it is known in the art to measure pressures and temperatures downhole and to relay the measured data to the surface using pressure modulated telemetry techniques. In such prior art implementations, pulsing of any measured data to the surface is not begun until the accelerometer measures a value that at least exceeds certain set thresholds or a pressure transducer samples data above a preset threshold.
To control the hydrostatic pressure of fluids in the formation 16 penetrated by the wellbore 10, the density of the drilling mud is controlled by various weighting agents known in the art. The weight of this mud often is controlled to prevent loss of well control or blowout. For example, a mud weight that exceeds the fracture strength of the exposed portion of the formation 16 below the casing 12 in the wellbore 10 can fracture the formation 16 and cause mud to be lost, and potentially result in loss of well control.
Alternatively, a mud weight that falls below the pore pressure of exposed portion of the formation 16 can allow an influx of fluid to occur in the wellbore 10. For example, a zone may be encountered in the formation 16 that has a higher pore pressure than the wellbore fluid pressure applied by the mud. This causes a “kick” or influx of formation fluid (liquid, gas, or both) into the wellbore 10 that can be detrimental to the operation. When such a kick occurs, rig operators perform well control operations to circulate the influx of formation fluid out of the wellbore 10 and regain control of the wellbore pressure for drilling.
Because the influx of formation fluid (liquid and/or gas) reduces the density of the drilling fluid in the wellbore annulus 14, the kick can be detected by evidencing a change in pressure in the wellbore annulus 14 or a change in mud density in the wellbore annulus 14, the kick can be detected by a gain in drilling fluid volume in the tanks or pits 42 for the mud system. When the kick is detected, rig operators then implement a well control operation to circulate the influx of formation fluids out of the wellbore 10 and regain control of the well again.
Two well control operations are widely used in the oil and gas industry to regain control after a kick. A first method is called the Wait & Weight (or Engineer's) method, while the second method is called the Driller's method. When a kick is detected in both methods, rig operators initially stop the mud circulation, shut-in the wellbore 10 using the blow-out preventer (BOP) 20, and measure the pressure buildup in the wellbore annulus 14, gain in the mud tanks 42, and shut-in pressure of the drill pipe 30. Calculations are then made to determine a kill weight of mud that has a high enough density to produce hydrostatic pressure at the point of influx in the wellbore 10 that will stop the flow of formation fluid into the wellbore 10.
Both the Engineer's and the Driller's methods have their advantages and disadvantages, and the choice of one method over the other may depend on various considerations, including operator preference as well as the circumstances involved in a particular well control situation such as the volume of the kick, the margin between the mud weight in the annulus 14 when the kick is taken and the minimum fracture gradient strength in the wellbore 10, and the increase required in mud weight to regain well control. Advantages of the Engineer's method include: (1) in many cases, only one circulation of the wellbore 10 is required to circulate out the kick and replace the original weight mud with kill weight mud, which can save rig time, and (2) in many cases, the maximum wellbore pressure at the last exposed casing shoe is less than the Driller's method, thereby reducing chances of fracturing the openhole during well control, which can require additional rig time to regain control. Advantages of the Driller's method include: (1) the implementation of the method is more straightforward because one circulation of the wellbore 10 is performed using the original weight mud to circulate out the kick, and a second circulation of the wellbore 10 is preformed using kill weight mud to regain well control, and (2) in some cases, the kick is circulated out of the wellbore 10 more quickly; for example, when significant time is required to increase the rig's active mud system to the necessary kill weight mud.
As an example of one of the two common methods, FIG. 1B shows a flow chart of the Engineer's method 100 according to the prior art. Although not shown in this flow chart, slow pump rates of the mud pumps 40 and choke/kill line friction tests are run at predetermined intervals during drilling prior to taking the kick. These slow pump rates are typically one-half to one-third of the normal circulation rate of the pumps 40 while drilling new formation. These tests and measurements help determine the frictional pressure losses created by flowing through the choke/kill line 50/60 for given mud properties at several flow rates. The intention of making these measurements prior to taking a kick is to be better prepared to implement well control operations should they become necessary. For example, the data and measurements help to optimize the mud flow rate during kill operations, with the goal of reducing the amount of time needed to regain well control while taking special care not to exert too high or too low of a pressure to the formation 16. While important in all drilling applications, these tests and measurements area of even greater importance when drilling with a subsea BOP 20 where the choke and kill lines 50/60 may be up to 10,000-feet in length and may produce more significant pressure losses in the choke and the kill lines, which greatly complicates maintaining wellbore pressure within the desired limits during the well control operations.
While drilling, a kick due to an influx of formation fluid (liquid, gas, or any combination thereof) into the wellbore 10 may be detected (Block 105). The well is shut-in by closing the BOP 20, and rig operators record the pressures at the surface on the drill pipe 30 (Shut-In Drill Pipe Pressure SIDP) and the casing 12 (Shut-In Casing Pressure SICP) using standard techniques (Block 110). The rig operators then fill out a standard “kill” sheet to outline the procedures for circulating out the influx and regaining well control (Block 115). As known in the art, the “kill” sheet is a spreadsheet or worksheet on which rig operators pre-record information about slow pump pressures at specific mud pump flow rates (psi @ SPM), choke line friction pressures at specific mud pump flow rates (psi @ SPM), true pump output (linear diameter, stroke length, and efficiency), drill string capacity and other details, annular capacity and other details, and the casing 12 specifics such as inner diameter, burst pressure rating, and the depth of the casing shoe Operators also input measurements such as Shut-in Drill Pipe Pressure (SIDPP), Shut-In Casing Pressure (SICP), and Pit Gain. Using information and calculations on the kill sheet, the rig operators can then determine the kill weight mud (KWM), initial circulation pressure (ICP), final circulating pressure (FCP), maximum allowable casing pressure (MCP), and pressure decline schedule for performing a well control operation.
Using the calculated weight required for the mud to kill the influx, rig operators “weight up” the active mud system by increasing the density of the drilling mud in tanks 42 using known techniques (Block 120). Then, the rig operators circulate the kill weight mud into the system by pumping it into the drill pipe 30 at a flow rate determined from the kill sheet (Block 125).
During the pumping, the rig operators monitor the pressures at the standpipe to ensure that the proper pressure is exerted on the formation 16 because pumping too heavy of a mud at too high of a rate could damage the formation 16 whereas too low of a pressure could cause an additional influx. Once the mud reaches the bit, the drill pipe pressure is recorded in order to adjust the choke 62 to keep the drill pipe pressure constant while the kill weight mud is circulated up the wellbore 10 to the surface.
Once a full circulation of kill weight mud has been pumped, the rig operators shut off the pumps 40 and monitor for pressure build up on the drill pipe 30 or the casing 12 (Block 135) and determine if there is a build up of pressure (Decision 140). Such a build up of pressure on the drill pipe 30 or casing 12 after shut-in would indicate that the influx has not been properly killed. If there is a build up, then the process must be repeated by closing the BOP 20, recording pressures, recalculating information in the kill sheet, etc. If there is no build up, then the uncontrolled flow of formation fluid into the wellbore 10 has been stopped, and the rig operators can resume normal drilling operations (Block 145).
In the Engineer's method described above as well as in the Driller's method, rig operators control pressure on the casing 12 and/or drill pipe 30 by adjusting the choke 62 that conducts the mud from the casing 12 to a mud reservoir (not shown) and by operating the mud pumps 40 at previously measured slow circulating (kill) rates and corresponding pressure. The length of the choke line 60 for a surface BOP stack is generally short enough to neglect the frictional pressure loss through the choke line 60 at the slow circulating rate. However, this is not the case for a subsea BOP, where the choke line 60 is generally at least several hundred feet long. In deepwater, the choke line 60 is generally thousands of feet in length. Hence, the pressure losses through the choke line 60 for subsea BOPs due to friction are significant even at slow circulating rates.
Therefore, to be prepared for well control, rig operators need to know slow circulating rate pressures and the friction pressure drops through the choke line (i.e., choke line friction pressures). To determine slow circulating rate pressures, for example, the rig operators pump drilling mud down the drill string 30 at various pump speeds and allow the returns to pass through the riser. This process obtains the slow circulating rate pressures used to calculate the initial circulation pressures (ICP) and final circulating pressures (FCP) for the kill sheet.
Various techniques can be used to determine the choke line friction pressures, such as by pumping at slow circulating rate pressures through the kill and choke lines with the rams closed. Before drilling is commenced, for example, rig operators can determine first slow circulating rate pressures from returns through the riser. Then, rig operators can open the choke 62 fully and measure second slow circulating pressures through the choke line 60. The choke line friction pressures at the various pump rates are calculated as the difference between these two slow circulating pressures. Regardless of how obtained, the choke line friction pressure must be adjusted for changes in mud properties.
As those skilled in the art will appreciate, it is important that well control operations be performed carefully. Operators attempting to control an influx may damage the formation 16 by exerting too great of a pressure on the formation 16. Any damage to the formation 16 can cause partial or complete loss of returns and can create situations that will take considerable time and additional strings of casing 12 to regain well control and return to normal drilling operations. In extreme cases, a substantial portion of the openhole wellbore 10 may be abandoned, requiring redrilling.
In the Driller's method, the rig operators must adjust the choke 62 on the choke line 60 to keep the casing pressure equal to the shut-in casing pressure minus the choke line friction pressure while the kill mud is pumped down the drill pipe 30. Because the bottom hole pressure is determined from the sum of the casing pressure at the surface, the annular pressure, and the choke line friction pressure, the accuracy and the reliability of pressure measurements and calculations can be particularly difficult to obtain reliably on deepwater drilling rigs using subsea BOP stacks. Use of inaccurate choke line friction pressures when circulating out a kick in such an implementation could result in either an increase or decrease in the bottom hole pressure that could damage the formation 16 or cause a secondary fluid influx.
Therefore, it is important that sound procedures be used to determine the choke line friction pressures. Unfortunately, obtaining choke line friction pressures periodically throughout the drilling process only provides for the mud properties at one moment in time. Friction pressure losses in the choke line 60, annulus 14, bit 32, and drillstring 30 vary significantly with changes in the mud properties such as density and viscosity. During normal drilling operations, and especially after a kick is taken, the mud properties can vary greatly based on factors such as mud weight, viscosity, and oil/water ratios. Consequently, the friction pressure losses will also generally change significantly when the original weight mud is weighted up to provide the kill weight mud.
In addition to the above problems, prior art well control operations can be time consuming and can require extensive planning, calculations, monitoring, and human intervention to execute. Furthermore, current well control operations are not open to much flexibility. As one example, the Engineer's method may require rig operators to construct a graphical or tabular pumping schedule of pump pressure versus volume pumped, and this pumping schedule must be followed by the rig operators during well control. In another example, both the Engineer's and Driller's methods for well control use substantially constant pump rates to maintain control while executing the operation, which is not always ideal or achievable. In the event it becomes necessary to change pumping rates and/or interrupt pumping during execution of the well control procedure, it frequently may be necessary to record new shut-in pressures, new circulating pressures, and recalculate an entirely new pumping and pressure schedule.
Not only do the prior art methods consume additional rig time and thereby increase costs to the operator and risks to the well control operations, but they also provide a less than optimal ability to determine accurate bottom hole pressure. As will be appreciated, the combination of mud, formation cuttings, and influx fluid(s) in the wellbore can vary significantly foot-by-foot and over time and can create uncertainty in the determination of the actual wellbore pressure in the annulus. Moreover, obtaining accurate choke line pressure losses poses another problem in determining the actual wellbore pressure in the annulus. This problem with accurate choke line pressure losses may be particularly acute on a subsea BOP and especially in deepwater, where the effects of temperature and pressure can cause choke line friction pressures to be significantly inaccurate.
Accordingly, systems and methods are needed that can facilitate well control operations by giving rig operators real-time downhole data during a well control operation to use when executing the operation. The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.